Abstract

Brine-based well treatment compositions containing alkali nitrate exhibit greater thermal stability when used in deep wells than substantially similar brine-based well treatment compositions which do not contain an alkali nitrate. The brine is thickened with a water-soluble crosslinkable polymer and crosslinking agent. The enhanced thermal stability of the well treatment compositions allows use of the fluids at elevated temperatures, for instance as high as 400° F.

Description

FIELD OF THE INVENTION

The invention relates to well treatment fluids which exhibit enhanced thermal stability and which contain a brine of an alkali nitrate and to methods of using such compositions.

BACKGROUND OF THE INVENTION

Aqueous based well treatment fluids are commonly used in drilling, stimulation, completion and workover operations of subterranean formations. Treatment designs typically mandate such fluids to exhibit a certain level of viscosity. Viscosifying polymers, such as polysaccharides, are often used in such fluids therefore to provide the requisite viscosity. For instance, the viscosifying polymer often provides the requisite level of viscosity needed to prevent the loss of well treatment fluids into the formation. In drilling fluids, such polymers serve to suspend solids and assist in floating debris out of the wellbore.

Unfortunately, the thermal stability of aqueous well treatment fluids containing a viscosifying polymer is often compromised as such fluids pass down the wellbore and are exposed to increasing temperatures. Temperatures in subterranean formations generally rise about 1° C. per hundred feet of depth. It is important, therefore, that such aqueous fluids are thermally stable at elevated temperatures.

Thermal instability typically causes degradation of the polymeric viscosifying agent which causes the viscosity of the well treatment fluid to decrease. A decrease in viscosity of a well treatment fluid often has detrimental effects on the wellbore treatment operation. For instance, a decrease in viscosity of drilling fluid often results in loss of suspension of drill cuttings which, in turns, results in the inability of such cuttings to float out of the wellbore. In addition, during drilling operations, degradation of the polymeric viscosifying agent may cause the drill string to bind in the wellbore and induce formation damage.

Ancillary to the need for maintaining viscosity, the well treatment fluid must have a sufficiently high density for the well treatment fluid to be operable at high temperatures and be able to withstand relatively high fluid pressures downhole.

High density brines have been found to have particular applicability in deep wells, such as those that descend 15,000 to 30,000 feet (4,500 to 10,000 meters) or more below the earth's surface, where it is most desirous to reduce pump pressure. Such brines have been found to be capable of maintaining the requisite lubricity and viscosity of the well treatment fluid under extreme shear, pressure and temperature variances encountered during operations of deep wells.

Exemplary of high density brines are sodium chloride, potassium chloride, calcium chloride, sodium bromide, calcium bromide, zinc bromide, potassium formate, cesium formate and sodium formate brines. While nitrate brines have been suggested for use in well treatment fluids such as completion and packer fluids, efforts to use such brines for such applications were abandoned, however, in the late 1950s after it was discovered that they contributed to stress corrosion cracking of carbon steels. Intergranular corrosion was further found to be caused when mixing chloride and nitrates. See, for instance, Hudgins and Greathouse, “Corrosion Problems in the Use of Dense Salt Solutions”, Corrosion, November, 1960, wherein it was reported the corrosion process could be inhibited by saturating the brine with lime or by keeping the pH above about 9. However, entrained carbon dioxide from the producing well reduced the pH of the brine. The use of such brines was, therefore, severely hindered.

One area of particular applicability for high density brines is in production stimulation treatments of deep wells wherein the brine fluid is used as a fracturing fluid. Pumping through work strings in such wells typically requires tremendous pressures. It is not uncommon that the amount of horsepower required for a job cannot be provided in light of the extremely high friction pressures generated during the pumping stage. In such instances, the hydrostatic pressure of a high density fluid counterbalances the pressure exerted by the fluid in the strata. In addition to having high density, the fracturing fluid must be highly viscous in order for it to suspend proppant. It is the proppant which is deposited into the created fractures and which prevents the formed fractures from closing after the completion of pumping. Conductive channels are thereby formed through which produced fluids may flow to the wellbore.

Unfortunately, under the severe wellbore conditions encountered in the treatment of deep wells, many viscosifying agents, particularly polysaccharides, degrade and depolymerize, thus losing their effectiveness.

As interest in treatment operations at deeper depths increases, there is a continual need for alternative well treatment fluids having enhanced thermal stability and which maintain their density at downhole conditions at least for two to three hours. It is further important that such alternative well treatment fluids be capable of reducing the requisite pump pressure generated during the well treatment operation.

SUMMARY OF THE INVENTION

A well treatment fluid containing a crosslinkable polymer, crosslinking agent and a brine containing alkali nitrate is capable of maintaining greater viscosity than a corresponding similar brine-based fluid which does not contain an alkali nitrate. The well treatment fluids defined herein further exhibit enhanced thermal stability when compared to similar brine-based fluids which do not contain an alkali nitrate. The well treatment fluids defined herein, in addition to exhibiting enhanced thermal stability, are further capable of maintaining their density when exposed to deep well conditions. For instance, the well treatment fluids defined herein may demonstrate enhanced thermal stability and maintain their density at downhole temperatures greater than or equal to 400° F.

The density of the brine based well treatment fluids defined herein is typically greater than or equal to 9.0, preferably between from about 9.0 to about 14.0. Typically, the brine is an admixture of an alkali nitrate and an alkali halide, such as sodium bromide.

The crosslinkable polymer of the well treatment fluids is typically guar, hydroxypropyl guar, xanthan gum, carboxymethylhydroxyethyl cellulose or hydroxyethyl cellulose.

The well treatment fluid further contains a crosslinking agent. A crosslinking agent, such as a borate crosslinking agent, is especially desirable when the crosslinkable polymer is guar or hydroxypropyl guar.

The well treatment fluid may be introduced into a wellbore exposed to high downhole temperatures without degradation of the fluid. The sustained viscosity of the well treatment fluid at such downhole temperatures ensures suspension of solids in the fluid as the fluid circulates through the wellbore.

The well treatment fluids defined herein have particular applicability when used in such well treatment operations as drilling, stimulation, completion, and workover. In a preferred embodiment, the well treatment fluid is introduced into a wellbore penetrating a subterranean formation and is used as a fracturing fluid. In another embodiment, the well treatment fluid is used to form, subsequent to its introduction into the wellbore, an impermeable barrier. As such, the well treatment composition is efficacious in reducing the loss of circulation fluids (such as drilling fluids, completion fluids and workover fluids) in the wellbore and/or into the flow passages of a formation during well drilling, completion and workover operations.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred in the Detailed Description of the Preferred Embodiments, a brief description of each drawing is presented, in which:

FIG. 1 is a viscosity profile of a well treatment composition containing sodium nitrate/sodium bromide brine.

FIG. 2 is a viscosity profile of a well treatment composition similar to that of FIG. 1 but containing only sodium bromide brine.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The thermal stability of aqueous well treatment fluids defined herein is improved by use of nitrate brine containing fluids. The viscosity and/or thermal stability exhibited by a well treatment fluid containing an alkali nitrate brine at a given downhole temperature is greater than the viscosity and/or thermal stability exhibited by a substantially similar well treatment fluid having the same pH, polymer, crosslinking agent and polymer loading but which does not contain an alkali nitrate containing brine.

As such, the presence of the nitrate brine serves to maintain stability of the fluid at a temperature greater than about 150° F., generally greater than 200° F. In most instances, the well treatment fluid defined herein demonstrates enhanced thermal stability at downhole temperatures in excess of 300° F. Typically, the well treatment fluid demonstrates enhanced thermal stability at a downhole temperature in excess of 350° F. Since temperatures in excess of 350° F. are typically encountered at well depths over 15,000 feet deep (4,500 m), the well treatment fluids defined herein have particular usefulness in deep well operations. The viscosity of the well treatment fluids defined herein is further maintained under the extremely high temperature, pressure and shear conditions seen in deep well operations.

Similarly, thermal stability at a desired temperature may be attained using less polymer with the well treatment fluids defined herein as compared to a substantially similar well treatment fluid which does not contain an alkali nitrate containing brine.

Further, the viscosity of a well treatment fluid introduced into a wellbore may be maintained over a longer time duration at a given temperature when a well treatment fluid defined herein is used as compared to a substantially similar well treatment fluid which does not contain an alkali nitrate containing brine. The well treatment fluids defined herein are typically capable of maintaining a viscosity greater than or equal to about 200 cP at about 40 sec−1 shear rate at a temperature of 325° F. for over 60 minutes. The ability of well treatment fluids defined herein to exhibit and maintain increased viscosity means that there is a reduced tendency for them to leak off into the formation. As such, the well treatment fluids defined herein are highly compatible when used as a fluid loss pill.

The density of the brine based well treatment fluid is typically greater than or equal to 9.0 and preferably is between from about 9.0 to about 14.0. In light of the enhanced stability of the well treatment fluid, the density of the fluid is maintained at the operating conditions of the wellbore.

The pH of the well treatment fluid is preferably selected such that chemical degradation of the fluid at operating conditions is minimized. The desired pH stability of the fluid is typically achieved when a pH of 8.0, more preferably 9.0, or greater is maintained. Suitable pH adjustment agents, such as soda ash, potassium hydroxide, sodium hydroxide and alkaline and alkali carbonates and bicarbonates, may be used to maintained the desired pH.

Typically the brine, in addition to containing an alkali nitrate salt, further contains an alkali halide, such as sodium bromide or sodium chloride. Typically the weight ratio of alkali halide to alkali nitrate in the brine is between from about 5:95 to about 95:5. As an example, a brine having a density of 13.1 ppg at 70° F. is often chosen since it may easily be prepared by adding enough sodium nitrate to a 12.5 ppg sodium bromide brine to render a saturated brine. Thus, the amount of alkali nitrate in the brine may be that amount sufficient to render a saturated brine. The admixture of salts may provide a brine having a density therefore which is higher than the density of a brine containing only one of the salts.

The nitrate brine of the well treatment fluid is thickened with a crosslinkable polymer. Generally, the well treatment fluid contains between from about 0.1 to about 5 wt % of crosslinkable polymer, preferably about 0.5 to about 4 weight %, even more preferably about 1 to about 3 weight %. Typical polymers include anionic or nonionic polysaccharides, such as cellulose, starch, galactomannan gums, polyvinyl alcohols, polyacrylates, polyacrylamides and mixtures thereof. Crosslinkable cellulose and cellulose derivatives include hydroxyalkyl cellulose, alkylhydroxyalkyl cellulose, carboxyalkyl cellulose and carboxyalkylhydroxyalkyl cellulose derivatives such as hydroxyethyl cellulose, hydroxypropyl cellulose, hydroxybutyl cellulose, hydroxyethylmethyl cellulose, hydroxypropylmethyl cellulose, hydroxylbutylmethyl cellulose, methylhydroxyethyl cellulose, methylhydroxypropyl cellulose, ethylhydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose and carboxymethylhydroxyethyl cellulose. Galactomannan gums include guar gum, hydroxyalkyl guar and carboxyalkylhydroxyalkyl guar and microbial polysaccharides include xanthan, succinoglycan and scleroglucan.

The fluid may further contain a crosslinking delay agent to control, along with the crosslinking agent, viscosification of the well treatment composition. Suitable crosslinking delay agents may include organic polyols, such as sodium gluconate; sodium glucoheptonate, sorbitol, mannitol, phosphonates, bicarbonate salt, salts, various inorganic and weak organic acids including aminocarboxylic acids and their salts (EDTA, DTPA, etc.) and citric acid and mixtures thereof. Preferred crosslinking delaying agents include various organic or inorganic acids, sorbitol as well as mixtures thereof.

Further, when used as a fracturing fluid, a delayed internal breaker may be included such that, once the proppant is placed in the fracture, the viscosity of the fluid may then be decreased in order to maximize flowback of the producing well. Delayed internal breakers can include but not limited to peroxides, enzymes, and esters or mixtures thereof.

Suitable crosslinking agents include a borate ion releasing compound, an organometallic or organic complexed metal ion comprising at least one transition metal or alkaline earth metal ion as well as mixtures thereof. Typically, the crosslinking agent is employed in the composition in a concentration of from about 0.001 percent to about 2 percent, preferably from about 0.005 percent to about 1.5 percent, and, most preferably, from about 0.01 percent to about 1.0 percent.

Borate ion releasing compounds which can be employed include, for example, any boron compound which will supply borate ions in the composition, for example, boric acid, alkali metal borates such as sodium diborate, potassium tetraborate, sodium tetraborate (borax), pentaborates and the like and alkaline and zinc metal borates. Such borate ion releasing compounds are disclosed in U.S. Pat. No. 3,058,909 and U.S. Pat. No. 3,974,077 herein incorporated by reference. In addition, such borate ion releasing compounds include boric oxide (such as selected from H3BO3 and B2O3) and polymeric borate compounds. An example of a suitable polymeric borate compound is a polymeric compound of boric acid and an alkali borate which is commercially available under the trademark POLYBOR® from U.S. Borax of Valencia, Calif. Mixtures of any of the referenced borate ion releasing compounds may further be employed. Such borate-releasers typically require a basic pH (e.g., 7.0 to 12) for crosslinking to occur.

Further preferred crosslinking agents are reagents, such as organometallic and organic complexed metal compounds, which can supply zirconium IV ions such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium diisopropylamine lactate; as well as compounds that can supply titanium IV ions such as, for example, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate. Zr (IV) and Ti (IV) may further be added directly as ions or oxy ions into the composition.

Such organometallic and organic complexed metal crosslinking agents containing titanium or zirconium in a +4 valence state include those disclosed in British Pat. No. 2,108,122, herein incorporated herein by reference, which are prepared by reacting zirconium tetraalkoxides with alkanolamines under essentially anhydrous conditions. Other zirconium and titanium crosslinking agents are described, for example, in U.S. Patent Publication No. 20050038199, herein incorporated by reference. Other suitable crosslinking agents are metal ions, metal containing species, or mixture of such ions and species. Such agents include Zn (II), calcium, magnesium, aluminum, Fe (II), and Fe (III). These may be applied directly to the composition as ions or as polyvalent metallic compounds such as hydroxides and chlorides from which the ions may be released.

Where the crosslinkable polymer is guar or hydroxypropyl guar, borate crosslinking agent is preferred.

Especially preferred as crosslinking agents include the crosslinking system disclosed in U.S. Pat. No. 5,145,590, herein incorporated by reference. This crosslinking system is a complexor solution of a crosslinking additive and a delay additive which controls the rate at which the crosslinking additive promotes gellation of the crosslinkable polymer. The control rate is a function of the pH of the complexor solution. The crosslinking additive is a material which supplies free borate ions in solution and the delay additive is a material which binds chemically the borate ions in solution, such that the crosslinkable polymer is forced to compete with the delay additive for the free borate ions. As such, the crosslinking additive can be any convenient source of borate ions, for instance the alkali metal and the alkaline earth metal borates boron monoxide and boric acid. A preferred crosslinking additive is sodium borate decahydrate. The delay additive is preferably selected from dialdehydes having about 1 to 4 carbon atoms, keto aldehydes having about 1 to 4 carbon atoms, hydroxyl aldehydes having about 1-4 carbon atoms, ortho substituted aromatic dialdehydes and ortho substituted aromatic hydroxyl aldehydes. The most preferred delay additive is glyoxal. The crosslinking additive is present in a preselected amount to provide a quantity of borate ions or boric acid sufficient to normally over-crosslink the crosslinkable polymer without the presence of the delay additive. The delay additive serves to mask the presence of at least a portion of the borate ions at low temperature, thereby providing a reserve of borate ions for cross-linking the fluid at higher temperatures and provide improved gel stability. Typically, borate compound is present from about 5 to 25% by weight of the complexor solution. The delay additive used in the complexor solution is a material which attempts to bind chemically to the borate ions produced by the cross-linking additive in solution, whereby the hydrated crosslinkable polymer is forced to compete with the delay additive for the borate ions. Preferably, the delay additive is selected from the group consisting of dialdehydes having about 1-4 carbon atoms, keto aldehydes having about 1-4 carbon atoms, hydroxy aldehydes having about 1 to 4 carbon atoms, ortho substituted aromatic dialdehydes and ortho substituted aromatic hydroxyl aldehydes. Preferred delay additives include, for instance, glyoxal, propane dialdehyde, 2-keto propanal, 1,4-butanedial, 2-keto butanal, 2,3-butadione, phthaldehyde, salicaldehyde, etc. The preferred delay additive is glyoxal. Preferably, the delay additive is present in the range from about 5 to 40% by weight of the complexor solution. The preferred ratio of delay additive to crosslinking additive ranges from about 1:0.1 to 1:1 and can approach 1:0.05.

The well treatment fluids defined herein may further include components suitable for modification of the rheological and chemical properties of the fluid. For instance, clayey (clay) materials, such as bentonite, attapulgite or sepiolite may be included in the well treatment fluid, when used as a drilling fluid, to lubricate the drill strings and suspend drill cuttings. The well treatment fluid may also include buffering agents or pH control additives such as sodium phosphate, sodium hydrogen phosphate, boric acid-sodium hydroxide, citric acid-sodium hydroxide, boric acid-borax, sodium bicarbonate, ammonium salts, sodium salts, potassium salts, dibasic phosphate, tribasic phosphate, lime, slaked lime, magnesium oxide, basic magnesium carbonate, calcium oxide and zinc oxide.

As indicated, the described well treatment fluids may be displaced into and used in a wellbore having high downhole temperatures without degradation of the fluid. The sustained viscosity of the well treatment fluid at such downhole temperatures ensures suspension of solids in the fluid as the fluid circulates through the wellbore. As such, the well treatment fluids defined herein have particular applicability when used in such well treatment operations as drilling, stimulation, completion, and workover. In a preferred embodiment, the well treatment fluids are used as fracturing fluids in hydraulic fracturing operations.

Further, the well treatment fluid may be effective in stopping or minimizing passage of fluid into a subterranean formation or into a wellbore by the creation of a fluid impermeable barrier. The barrier results upon viscosification of the fluid. Subsequent to its introduction into the wellbore as a pumpable composition, the well treatment fluid viscosifies and thickens into a highly viscous gel. The impermeable barrier reduces or eliminates the loss of wellbore fluid into the wellbore and/or the subterranean formation. After formation of the impermeable barrier, drilling, cementing, completion or workover is resumed. Viscosification of the fluid is inhibited until after the composition is introduced into or near the formation or targeted area. The presence of the crosslinking delay agent allows the well treatment fluid to be easily pumped into the wellbore.

The following examples will illustrate the practice of the present invention in its preferred embodiment. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the specification and practice of the invention as disclosed herein. It is intended that the specification, together with the examples, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow.

EXAMPLESExample 1

A solution was prepared by mixing 0.908 bbl of 12.5 ppg NaBr and 72.7 ppb of 99.9% sodium nitrate. The sodium nitrate completely dissolved and the solution was measure to have a density of 13.12 ppg at 76° F. The crystallization temperature of the fluid was measured to be 60° F.

Example 2

To the solution in Example 1, 40 Ib/Mgal (1.68 ppb) of guar gum was added using an overhead stirrer. The solution reached maximum viscosity at 511 l/sec of 55 cp. in 15 minutes. The fluid without the guar gum had a viscosity of 3.6 cp. at 511 l/sec. The pH of the fluid was raised to 11.2 with 25% by weight NaOH and 0.15 ppb of sodium tetraborodecahydrate was added to crosslink the guar gum. The fluid was then heated to 180° F. and the rheologies measured on an OFI Model 900 viscometer at 180° F. The viscosities at shear rates of 1022, 511, 340, 170, 10, 5 l/sec is 85, 120, 169, 278, 1,100 and 1,420 cp., respectively, indicating that the fluid was crosslinked.

Comparative Example 3

A brine slurry was prepared containing 40 ppg of guar (commercially available as GW-3LE from BJ Services Company) in 12.5 ppg sodium bromide. The fluid was mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 15.0 gallons per thousand gallons of a potassium containing buffer capable of adjusting the pH of the fluid to a range of about 11.9, commercially available as BF-9L from BJ Services Company; 15.0 gallons per thousand gallons of a borate delayed crosslinking agent (commercially available as XLW-56 from BJ Services Company); and 8.0 pounds per thousand gallons of sodium thiosulfate oxygen scavenger. Thereafter, 45 ml sample of the fluid was placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly. The cup was then placed on a Fann 50 viscometer. The sample was sheared by a rate sweep of 100 sec−1 for about 1 minute. The sample was then subjected to different shear rates at varying temperatures. The stresses associated to each rate used in the sweep together with the sweep rate were then used to calculate the power law indices n and K; n refers to flow behavior index and K refers to consistency index set forth in the American Petroleum Institute's Bulletin RP-39. The fluid viscosity was then calculated by using the n and K values, and listed in Table I. The initial linear viscosity was 60 cP at 80° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE I

Time

Temperature

n′

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

(lb (f)/ft2) (sec)

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

260

0.3578

34.8637

1562

867

617

10

287

0.2617

44.5075

1399

711

481

20

296

0.3602

29.2462

1322

735

524

30

300

0.8870

2.6705

843

760

716

40

300

1.6225

0.0752

358

633

881

50

300

2.3299

0.0022

142

481

975

Example 4

A brine slurry was prepared containing 40 ppg of GW-3LE guar in 13.1 ppg sodium bromide/sodium nitrate and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 4.5 gallons per thousand gallons of BF-9L, 0.10 gallons per thousand gallons of BF-10L. 3.0 gallons per thousand gallons of XLW-56 and 1.0 gallons of a borate crosslinking agent, commercially available from BJ Services Company as XLW-32 was also added along with 8.0 pounds per thousand gallons of sodium thiosulfate oxygen scavenger and 0.50 pounds per thousand gallons of a peroxide delayed release oxidative breaker, commercially available as GBW-24 from BJ Services Company. Thereafter, 65 ml sample of the fluid was placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly fluid viscosity calculated as set forth in Example 3 above. The results are shown in Table II. The initial viscosity was 87 cP at 76° F.

TABLE II

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

94

0.4179

35.9570

2011

1179

866

10

249

0.2031

84.9472

2151

1036

679

20

278

0.3878

32.9626

1649

941

680

30

300

0.1906

71.0904

1719

819

533

40

300

0.2631

56.5441

1786

909

615

50

300

0.2912

52.8759

1853

968

664

60

300

0.2951

54.4192

1934

1014

698

70

300

0.4245

29.3440

1681

992

731

80

300

0.6252

14.9912

1801

1277

1047

90

300

0.8099

6.2326

1480

1243

1124

100

300

0.6746

11.3899

1642

1218

1025

110

300

1.0789

1.7382

1113

1197

1248

120

300

1.2071

0.8912

916

1107

1236

130

300

1.3567

0.4228

755

1046

1264

140

300

1.5201

0.1909

622

1003

1321

150

300

1.7041

0.0762

490

934

1357

160

300

1.9962

0.0183

346

861

1461

170

300

2.1569

0.0077

263

759

1403

180

300

2.2499

0.0045

217

681

1322

210

300

2.1610

0.0048

166

482

893

240

300

1.2395

0.1133

131

163

186

270

300

0.6374

0.9090

114

82

68

300

300

0.4987

1.3640

103

65

50

A comparison of Table I with Table II shows a higher viscosity (cP) for the composition containing sodium nitrate than the corresponding composition not containing the sodium nitrate and that the fluid retains viscosity for a longer time.

Example 5

A brine slurry was prepared containing 40 ppg of GW-3LE guar in 13.1 ppg sodium bromide/sodium nitrate and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 15.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 12.2 and 0.75 gallons per thousand gallons of BF-10L and 7.0 gallons per thousand gallons of XLW-56 and 1.0 gallons of XLW-32. 20.0 pounds per thousand gallons of sodium thiosulfate oxygen scavenger was also added. Thereafter, 45 ml sample of the fluid was placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly fluid viscosity calculated as set forth in Example 3 above. The results are shown in Table III. The initial linear viscosity was 83 cP at 82° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE III

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

101

0.2052

73.6451

1879

907

595

10

265

0.2072

84.3219

2167

1048

688

20

306

0.1157

96.1381

1763

784

490

30

320

0.4178

28.0855

1570

921

676

40

323

0.6144

10.3184

1191

837

682

50

323

0.9680

2.0029

852

827

814

60

323

1.2236

0.5923

647

794

894

70

323

1.6234

0.0937

447

792

1102

80

325

2.1509

0.0054

180

518

954

When compared with Comparative Example 3, the fluid of Example 5 demonstrated enhanced thermal stability and viscosity at higher temperature.

Example 6

Example 5 was repeated except that the brine slurry contained 50 ppg of guar. The calculated viscosity is set forth in Table IV. The initial linear viscosity was 100 cP at 78° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

The procedure of Example 6 was repeated using 50 ppg polymer loading except that 11.0 ppg sodium bromide/sodium nitrate was used. The fluid contained 15.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 12.1, 0.10 gallons per thousand gallons of BF-10L, 7.0 gallons per thousand gallons of XLW-56, 1.0 gallons of XLW-32 and 20.0 pounds per thousand gallons of sodium thiosulfate. The initial linear viscosity was 79 cP at 83° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1. The viscosity results are illustrated in Table V.

A brine slurry was prepared containing 50 ppg of GW-3LE guar in 11.0 ppg sodium nitrate brine and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 15.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 12.2 and 7.0 gallons per thousand gallons of XLW-56 and 1.0 gallons of XLW-32. 20.0 pounds per thousand gallons of sodium thiosulfate oxygen scavenger was also added. Fluid viscosity was determined in accordance with the procedure set forth in Example 3 above. The results are shown in Table VI. The initial linear viscosity was 84 cP at 78° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE VI

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

101

1.2346

2.2536

2563

3178

3599

10

265

0.2893

45.5669

1585

827

567

20

306

0.2940

50.9491

1804

945

649

30

320

0.3285

42.8444

1723

931

652

40

320

0.2218

66.9049

1815

890

589

50

320

0.3954

31.1814

1605

922

669

60

320

0.4281

27.0695

1572

931

687

70

320

0.4959

20.4952

1528

963

737

80

320

0.5888

13.5870

1427

979

787

90

320

0.6984

8.8342

1390

1055

899

100

320

0.8383

4.8514

1279

1103

1012

110

320

0.9121

3.3567

1162

1072

1023

120

320

0.9975

2.2591

1072

1069

1068

130

320

1.0497

1.7077

982

1028

1055

140

320

1.0949

1.4244

968

1056

1110

150

320

1.1492

1.0174

845

968

1048

160

320

1.2143

0.7570

799

972

1089

170

320

1.3324

0.4330

707

958

1143

180

320

1.3723

0.3271

618

870

1060

190

320

1.5052

0.1680

519

824

1077

200

320

1.6686

0.0759

428

790

1126

210

320

1.9064

0.0241

327

750

1213

220

325

1.9181

0.0119

168

391

636

230

325

1.9204

0.0107

153

355

579

240

325

1.8419

0.0131

140

303

473

250

325

1.7978

0.0143

130

270

412

260

325

1.7262

0.0157

110

213

313

270

325

1.5069

0.0314

98

155

203

280

325

1.2597

0.0717

89

114

130

290

325

1.0146

0.1702

86

87

88

300

325

0.7915

0.3495

78

64

57

Table VI demonstrates that excellent viscosity and thermal stability is obtained by use of a brine containing solely sodium nitrate.

Example 9

A brine slurry was prepared containing 25 ppg of GW-3LE guar in 13.1 ppg sodium bromide/sodium nitrate brine and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 4.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 11.4 and 0.10 gallons per thousand gallons of BF-10L. 1.250 gallons per thousand gallons of XLW-30, a borate ore slurried in hydrocarbon oil, a product of BJ Services Company. Thereafter, 45 ml sample of the fluid was placed into a Fann 50 viscometer cup having a bob (BX5) and rotor (R1) cup assembly fluid viscosity calculated as set forth in Example 3 above. The results are shown in Table VII. The initial linear viscosity was 40 cP at 73° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE VII

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

79

0.6439

0.7586

98

70

58

10

200

0.6342

1.8378

228

163

134

20

228

0.5692

4.7303

462

311

248

30

250

0.6103

4.5286

515

360

293

40

250

0.6389

4.2269

534

384

317

50

250

0.6638

3.8889

539

396

331

60

250

0.6807

3.6332

536

400

337

70

250

0.6443

4.3298

558

403

334

80

250

0.6040

5.2872

587

409

331

90

250

0.6312

4.7101

578

413

339

100

250

0.5834

5.8579

603

412

330

110

250

0.6807

3.6738

542

404

341

120

250

0.6973

3.3450

524

397

338

130

250

0.7156

3.0482

511

394

339

140

250

0.7553

2.5233

490

391

344

150

250

0.7657

2.3948

483

390

344

160

250

0.7848

2.1592

467

384

342

170

250

0.7848

2.1491

465

382

341

180

250

0.7809

2.1796

465

380

339

190

250

0.7949

2.0206

454

376

337

200

250

0.8002

1.9473

446

371

334

210

250

0.7947

2.0110

451

374

335

Table VII illustrates that use of nitrate brines at lower temperatures allows the application of lower polymer loadings to achieve acceptable viscosity and thermal stability.

Example 10

A brine slurry was prepared containing 20 ppg of GW-3LE guar in 13.1 ppg sodium bromide/sodium nitrate brine and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 5.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 11.4 and 0.10 gallons per thousand gallons of BF-10L and 3.0 gallons per thousand gallons of XLW-56 and 1.0 gallons. 0.50 pounds per thousand gallons of GBW-24 was also added. Thereafter, fluid viscosity was determined as set forth in Example 3 above. The results are shown in Table VIII. The initial linear viscosity was 37 cP at 73° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE VIII

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

83

0.6654

0.9290

129

95

80

10

180

0.2911

7.8349

274

143

98

20

203

0.4532

6.6854

426

258

193

30

225

0.6829

3.4537

513

384

324

40

225

0.7930

2.1812

487

403

361

50

225

0.8250

1.9220

482

411

375

60

225

0.8751

1.5342

463

413

387

70

225

0.8634

1.6199

469

413

385

80

225

0.7840

2.3935

517

424

378

90

225

0.7994

2.2932

524

436

392

100

225

0.6874

3.9736

600

451

382

110

225

0.7510

3.0444

582

463

406

120

225

0.6782

4.2705

624

464

392

130

225

0.6861

4.0953

616

462

391

140

225

0.6555

4.7847

643

469

390

150

225

0.6760

4.2990

623

463

390

160

225

0.7151

3.5481

594

457

393

170

225

0.7140

3.5033

584

449

386

180

225

0.7067

3.6456

592

452

387

190

225

0.7577

2.9078

569

456

401

200

225

0.6937

3.9093

605

457

388

210

225

0.6801

4.4804

659

492

415

Table VIII further illustrates that use of sodium bromide/sodium nitrate brines at lower temperatures allows the application of lower polymer loadings to achieve acceptable viscosity and thermal stability.

Comparative Example 11

A brine slurry was prepared containing 20 ppg of GW-3LE guar in 12.5 ppg sodium bromide and mixed for 30 minutes using an overhead stirrer. To the fluid was then added, 5.0 gallons per thousand gallons of BF-9L to adjust the pH of the fluid to a pH of 11.6 and 0.10 gallons per thousand gallons of BF-10L and 3.0 gallons per thousand gallons of XLW-56 and 1.0 gallons. 0.50 pounds per thousand gallons of GBW-24 was also added. Thereafter, fluid viscosity was determined as set forth in Example 3 above. The results are shown in Table IX. The initial linear viscosity was 27 cP at 72° F. measured on a Chandler 3500 rheometer having a bob (B1) and rotor (R1) cup assembly at a rate of sweep of 511 sec−1.

TABLE IX

Time

Temperature

K′

40 1/sec

100 1/sec

170 1/sec

Minutes

° F.

n′

lb (f)/100 ft2

Viscosity (cP)

Viscosity (cP)

Viscosity (cP)

0

92

0.1587

9.4717

204

94

60

10

185

0.0442

42.7043

602

251

151

20

206

0.7686

1.1901

243

196

174

30

225

2.2012

0.0007

30

89

169

The data of Tables VIII and IX is graphically represented in FIG. 1 and FIG. 2, respectively. The FIGs. show the difference between a sodium bromide brine versus an sodium nitrate/sodium bromide brine. The FIGs. show that the viscosity is maintained over a longer period of time at elevated temperature when a sodium nitrate/sodium bromide brine is used compared to sodium bromide brine.

In light of the enhanced viscosity and thermal stability over time, as demonstrated by the data above, such materials provide an excellent resource in the enhancement of lost circulation materials.

From the foregoing, it will be observed that numerous variations and modifications may be effected without departing from the true spirit and scope of the novel concepts of the invention.

Claims (20)

1. A method of treating a hydrocarbon-bearing subterranean formation which comprises pumping into a well penetrating the formation a well treatment fluid having a pH greater than or equal to 9.0, the well treatment fluid comprising an alkali nitrate brine having a density greater than or equal to 12.5 ppg at 70° F., a crosslinkable polymer selected from the group consisting of guar gum, hydroxyalkyl guar and carboxyalkylhydroxyalkyl guar and a crosslinking agent; wherein the viscosity of and thermal stability exhibited by the well treatment fluid at the downhole temperature is greater than the viscosity of and thermal stability exhibited by a substantially similar brine-based well treatment fluid which does not contain an alkali nitrate salt.

2. The method of claim 1, wherein the alkali nitrate brine further comprises an alkali halide.

3. The method of claim 2, wherein the alkali halide is sodium bromide.

4. The method of claim 2, wherein the alkali nitrate brine is composed a 95:5 to 5:95 weight ratio of alkali nitrate:alkali halide.

5. The method of claim 1, wherein the downhole temperature is in excess of 150° F.

6. The method of claim 5, wherein the downhole temperature is in excess of 300° F.

7. The method of claim 6, wherein the downhole temperature is in excess of 350° F.

8. The method of claim 1, wherein the density of the alkali nitrate brine is between from about 12.5 to about 13.1 at 70° F.

9. The method of claim 1, wherein the density of the well treatment fluid is greater than or equal to 12.8 ppg at 70° F.

10. The method of claim 8, wherein the density of the well treatment fluid is 13.1 ppg at 70° F.

11. The method of claim 1, wherein the brine-based well treating composition is pumped into a propagated fracture or into the subterranean formation at a pressure sufficient to fracture the formation.

12. The method of claim 11, wherein the brine-based well treatment fluid further comprises a proppant.

13. The method of claim 1, wherein the brine-based well treatment fluid further comprises a delayed internal breaker.

14. The method of claim 1, wherein the well treatment composition further comprises a crosslinking delaying agent.

15. The method of claim 1, wherein the alkali nitrate brine is a sodium nitrate brine.

16. A method for reducing the loss of fluids into flow passages of a subterranean formation during well drilling, completion, or workover operations which comprises introducing into the flow passages an effective amount of a well treatment composition having a pH greater than or equal to 9.0, the well treatment composition comprising a brine containing an alkali nitrate having a density greater than or equal to 12.5 ppg at 70° F., a crosslinkable polymer selected from the group consisting of guar gum, hydroxyalkyl guar and carboxyalkylhydroxylalkyl guar and a crosslinking agent and then viscosifying the well treatment composition, thereby reducing the loss of fluids into the flow passages upon resuming of the well drilling, completion or workover operation.

17. The method of claim 16, wherein the well treatment composition reduces the loss of drilling fluids, completion fluids or workover fluids into the flow passages of the formation.

18. The method of claim 16, wherein the alkali nitrate is sodium nitrate.

19. The method of claim 16, wherein the density of the well treatment composition is greater than or equal to 12.8 ppg at 70° F.

20. A method of treating a well in communication with a subterranean formation penetrated by a wellbore which comprises:

(a) introducing a pumpable well treatment composition having a pH greater than or equal to 9.0, the well treatment composition comprising a sodium nitrate brine having a density greater than or equal to 12.5 ppg at 70° F.; a crosslinkable polymer selected from the group consisting of guar, hydroxypropyl guar and carboxyalkylhydroxyalkyl guar; and a crosslinking agent into the well;

(b) increasing the viscosity of the well treatment composition; and

(c) forming a fluid-impermeable barrier within the formation or within the wellbore from the composition resulting from step (b) and thereby reducing the permeability of the formation, mitigating loss of fluid into the formation and/or reducing fluid communication within the wellbore.

US120306142008-02-132008-02-13Method of treating a well and a subterranean formation with alkali nitrate brine
Active2029-02-21US8003578B2
(en)